Williams, Neil Jason (Superior Completions Services) | Kelly, Patrick A. (Superior Energy Services) | Berard, Kelly G. (Superior Energy Services) | Dore', Ethel (Superior Energy Services) | Emery, Nathan L. (Superior Energy Services) | Williams, Chad F. (Superior Energy Services) | Mukhopadhyay, Sumitra (Superior Energy Services)
Guar-based crosslinked fluids are most commonly used in hydraulic fracturing to stimulate oil and gas wells. When crosslinked with boron, the fluid not only provides high viscosity, it is also able to recover its rheological properties after being subjected to a mechanical shear. Although borate crosslinked guar systems are environmentally favorable, the gelled fluids generate a significant amount of insoluble residues upon breaking down with oxidizers or enzymes, commonly known as breakers. The amount of residues formed in the broken fluid is directly related to the type and the quantity of the polymer used. Studies have shown that these residues can cause significant damage to the formation and to the proppant pack conductivity. So it is highly sought-after to formulate an efficient boron-crosslinked fluid system with lower polymer loading without compromising its rheological properties and proppant carrying ability. In addition, the recent global shortage of the guar beans specifically required for the oil & gas industry has driven our efforts further toward this goal.
Studies have shown that crosslinking efficiency is dependent on the availability of the crosslinking sites and the chemical and structural properties of the crosslinkers. Considering these factors two different approaches were taken in order to reduce the polymer loadings of the fracturing fluid: 1) Use of a high yielding, fast hydrating, non-derivatized guar system with appreciably less insoluble materials and 2) Use of a new set of chemically modified boron crosslinkers with higher crosslinking efficiency. This paper will describe the laboratory testing involved in developing this new generation of low-cost, low-polymer, and environmentally responsible fracturing fluids. The fluid is operable in a broad range of temperature and compatible with breakers and additives commonly used in the industry. This system has the capacity to withstand high salinity and high shear rates, and is capable of rapid re-heal, which decreases shear degradation as the fluid is pumped through gravel pack tools. The paper will also discuss our recent fluid testing in preparation for pumping in the Gulf of Mexico.
Formation integrity is a critical confinement factor in any injection process such as waste injection, CO2 capture and storage, and thermal/pressure injection in oilfields. Rock can fail in tensile, shear or in combination of complex modes. In situ stresses variation caused by injection may shear the caprock posing continued risk of containment breach. We developed an integrated approach to predict the alteration of in situ stresses and shear failure potential by combining data from sonic logs, image logs, mini-frac test data, formation pressure measurement, and rock mechanical core test data. In this approach, three-dimensional Mechanical Earth Models containing the reservoir, overburden, under-burden and side-burden were constructed. Coupled simulations were then run between dynamic reservoir model and geomechanical model to quantify stresses change induced by injection. The resulted formation shear and surface heave will then be calculated regarding the location and timing of occurrence during the planed injection operations.
The methodology has been applied to several steam injection case studies in Northern Alberta oil sands area, Canada. Our analysis indicated that three years of steam injection would cause up to 2 MPa stresses contrast; formation shear failure was forecasted to occur earlier than formation tensile failure at a same time step; the calculated surface heave due to steam injection was around three 3 cm. The simulation results enabled the optimization of injection scheme and proactive monitoring plans to avoid catastrophic events.
It is widely understood that injection activities can induce additional stress fields that will couple with the original in situ stress field. An increased shear stress may cause serious formation shear issue, which will in turn compromise the integrity of caprock or/and casings. In Northern Alberta, Canada, caprock unintegrity is an important environmental concern in heavy oil thermal production. Steam Assisted Gravity Drainage (SAGD) and Cyclic Steam Stimulation (CSS) are the two most popular thermal oil recovery methods in heavy oil reservoirs where the oil in the form of bitumen is essentially immobile [Butler, 1991, Clark, 2007].
Steam injection triggers complex thermal and hydraulic processes which can dramatically alter the formation pressure and temperature leading to various changes within the reservoir as well as in the surrounding rock. As steam is injected into reservoir, the pressure and temperature in the reservoir rise. The increased temperature and pressure cause changes in in situ stresses, rock properties, porosity, permeability, etc. High temperature and injection pressure can reduce rock strength, induce fractures. This poses a continued risk of breaching the containment of caprock, which can provide pathways for bitumen and steam to flow to aquifers or to the surface causing significant risk to safety and the environment. Therefore, ensuring caprock integrity is critical in any subsurface injection process such as SAGD and CSS.
Conventionally, fracture pressure typically measured/interpreted from mini-fracturing (mini-frac) test is considered as the upper limit of the net injection pressure. However, some cases of compromising the integrity of caprock have been reported despite keeping the net injection pressure below the fracture pressure. These cases clearly indicate that designing the injection pressure scheme solely based on mini-frac test is not sufficient. Because, fracture pressure estimated from mini-frac test considers tensile failure only. Rock can fail in tensile, shear or in combination of complex modes. Consideration of shear failure in addition to tensile failure must be an essential part of caprock integrity analysis.
Coreflood experiments are an integral part of the selection and optimisation of scale inhibitor treatments, providing information on formation damage, inhibitor return profiles and dynamic retention isotherms. Comparative returns are often used to select the chemical for field treatments. However, significant discrepancies can arise between core and field in particular due to test methodology.
Here we describe advances over previous work when we demonstrated that test methodology can have significant consequences for the comparative inhibitor returns, particularly with respect to oversaturation. It was shown that many of the limitations can be overcome through appropriate simulation techniques (see SPE 131131).
Here, we present the results of laboratory core flood tests designed to examine the effect of core flood test methodology on the derived return isotherm. This work clearly identifies certain test artefacts, in particular inhibitor oversaturation, which can impact simulation from core to field, and presents supportive core flood data with respect to the modelled isotherms. Thus the paper directly addresses the procedures involved in core flooding, recommends approaches and test protocols which allow more appropriate product ranking and allow improved simulation from core to field.
Germanovich, Leonid N. (Georgia Inst. of Technology) | Hurt, Robert S. (Georgia Inst. of Technology) | Ayoub, Joseph Adib (Schlumberger) | Siebrits, Eduard (Schlumberger) | Norman, David (Chevron Corp.) | Ispas, Ion (BP plc) | Montgomery, Carl T. (ConocoPhillips Company)
In this work, we argue that resistance (apparent toughness) to fracture propagation is an inherent characteristic of cohesionless particulate materials. We developed experimental techniques to quantify the initiation and propagation of fluid-driven fractures in saturated particulate materials. The fracturing liquid is injected into particulate materials, where the fluid flow is localized in thin, self-propagating, crack-like conduits. By analogy, we call these conduits ‘cracks' or ‘hydraulic fractures.' The experiments were performed on three particulate materials - (1) fine sand, (2) silica flour, and (3) their mixtures. Based on the laboratory observations and scale (i.e., dimensional) analysis, this work offers physical concepts to explain the observed phenomena. The goal of this study is to determine the controlling parameters of fracture behavior and to quantify their effects.
When a fracture propagates in a solid, new surfaces are created by breaking material bonds. Consequently, the material is in tension at the fracture tip. In contrast, all parts of the cohesionless particulate material (including the tip zone of the hydraulic fracture) are likely to be in compression. In solid materials, the fluid front lags behind the front of the propagating fracture. However, for fluid-driven fractures in cohesionless materials the lag zone is absent. The compressive stress state and the absence of the fluid lag are important characteristics of hydraulic fracturing in particulate materials with low, or negligible, cohesion. At present, two kinematic mechanisms of fracture initiation and propagation, consistent with both the compressive stress regime and the absence of the fluid lag, can be offered. The first mechanism is based on shear bands propagating ahead of the tip of an open fracture. The second is based on the reduction of the effective stresses and material fluidization within the leakoff zone at the fracture tip.
Our experimental results show that the primary factor affecting peak (initiation) pressure and fracture aperture is the magnitude of the confining stresses. The morphology of the fracture and fluid leakoff zone, however, changes significantly not only with stresses, but also with other parameters such as flow rate, fluid rheology, and permeability. Typical features of the observed fractures are multiple offshoots (i.e., small branches, often seen only on one side of the fracture) and the bluntness of the fracture tip. This suggests the importance of inelastic deformation in the process of fracture propagation in cohesionless materials. Similar to solid materials, fractures propagate perpendicular to the least compressive stress.
Scaling indicates that in the experiments performed in the regime of limited leakoff (i.e., the thickness of the leakoff zone is much smaller than the fracture length); there is a high-pressure gradient in the leakoff zone in the direction normal to the fracture. Fluid pressure does not decrease considerably along the fracture, however, due to the relatively wide fracture aperture. This suggests that hydraulic fractures in unconsolidated materials propagate within the toughness-dominated regime. This is the main conclusion of our work. In addition, the theoretical model of toughness-dominated hydraulic fracturing can be matched to the experimental pressure-time dependences with only one fitting parameter. Scale analysis shows that large apertures at the fracture tip correspond to relatively large 'effective' fracture (surface) energy, which can be orders of magnitude greater than typical for hard rocks.
In this work, we present a comprehensive experimental development focusing on four main parameters: (1) confining stresses, (2) fluid rheology, (3) injection rate, and (4) permeability. Another important conclusion is that the primary parameter in determining the peak injection pressure is that of confining stresses.
Unconventional plays require multiple hydraulic fracture treatments placed in vertical or horizontal wellbores in order to be economical. These are very complex operations performed on-location in an orchestrated manner by many contributors. A screenout puts many of the contributors on stand-by status, delays the placement of subsequent stages, and, results in cost overruns due to stand-by charges, wellbore cleanout operations, and, lost production days. Thus, advanced warning of screenouts is a major technical advance in hydraulic fracturing.
Advanced warning of screenouts in real-time is a great advantage due to the ability to exercise decision control for early termination of the treatment, or extension of the treatment.
A screenout is imminent if the surface pressure slope deviates from the inverse slope (positive surface pressure slope). This allows for early initiation of the displacement (flush) procedure, and prevents leaving in the wellbore excess proppant. When only the designed amount of proppant is left in the wellbore high net-pressure develops, along with adequate packing of the near-wellbore area and a much wider fracture.
A treatment can be extended if the surface pressure slope doesn't deviate from the inverse slope (positive surface pressure slope). Thus, if extra fluid and proppant are available on location the treatment can be extended. This would result in a much better placement of the proppant pack, as it would result in a higher net-pressure, a wider fracture, and higher production rates.
The present work investigates the impact of high temperature on fines migration and is useful for both sandstone and shale formations at high temperatures. The results show subsequent loss of permeability in clay-containing rocks such as sandstone. Three types of clays are present in sandstone rock used for
experiments: kaolinite, illite, and chlorite. Both experimental and theoretical results of conducted coreflood experiments show that the rise in temperature sensitizes fines, and thus decreases sandstone permeability significantly upon the injection of fresh water.
Coreflood experiments were performed at 74, 200, and 300°F temperatures. Brine, 5 wt% NaCl was injected at room temperature to determine the initial rock permeability. Next, temperature was applied to the system, and various potential clay stabilizing salts, as well as fresh water flooding, was performed in both forward and reverse directions to confirm plugging. Core effluent was collected during each experiment and analyzed to measure the concentration of key cations using ICP-OES.
The experimental results were verified by application of the DLVO theory. The mathematical model was used to evaluate the magnitude and determine the effect of each of the contributing forces. The results show that the double layer repulsion force has the most significant impact, due to change in
temperature of the matrix-clay system.
Based on the results attained, it can be concluded that fines migration is a serious problem in sandstone formations at high temperatures. High salt concentrations or salts containing high valency cations will be required to mitigate fines migration due to pH changes at higher temperatures. From experimental results obtained, 15 wt% NaCl and 15 wt% HCl solutions were able to preserve permeability in the rock and minimize fines migration at elevated temperatures. This paper will discuss experimental and theoretical studies conducted that highlight the importance of fines migration in high temperature wells.
Sourget, Adrien (Schlumberger) | Milne, Arthur (Schlumberger) | Diaz Torres, Lenin (Schlumberger) | Lian, Eric Gin Wai (Schlumberger) | Larios Leon, Humberto (Schlumberger) | Tejeda, Patricio (Pemex) | Macip, Miguel (Pemex E&P)
Water control is one of the greatest challenges in Southern Mexico wells, where the reservoirs are generally fractured carbonates. Many of the wells have early water breakthrough as a result of one or more of the following: water coning, near-wellbore flow, high-conductivity channels, high-conductivity layer breakthrough, segregated layering, and inadequate completions.
In cases where it is possible to shut off the producing interval and recomplete the well in a new interval, reticulated polymer gels and/or cement slurries can control water production. However, when the water is produced in a different interval than the oil, the success rate of reducing the water cut is less than 30%.
In these cases, waterless cement slurry squeezes have proven to be an effective solution to unwanted water production. This method has been used to successfully reduce water cut in several fields in South Mexico with a nearly 100% success rate.
A well which was carefully evaluated as a candidate and then treated with a waterless cement slurry resulted in a reduction in water cut from 71% to 5%, while oil production increased from 290 barrels of oil per day (BOPD) to 1054 BOPD. In addition, the deferred production was greatly reduced using this technique—less than four days compared with several weeks using alternative techniques.
Water cement squeezes are a cost-effective way to reduce water production in the producing intervals of naturally fractured reservoirs. This technique has increased oil production while resulting in significant cost savings in terms of both treatment costs and deferred production.
Fluid loss control is an essential property of oil based mud (OBM) which can impact the success of drilling operations. The paper presents an investigation of the mitigation of lost circulation in OBM using leak-off control additive. A simple physical model was developed to describe the static filtration process considering the formation and properties of the filter cake. Both HTHP API press and core flow filtration experiments were performed to evaluate the leak-off behavior of OBM. Core filtration experiments were carried with the aid of a CT scanner to monitor the invasion of the filtrate into the sandstone core at time intervals. In the long time limit the model predicts that the fluid loss follows the classical Carter equation, i.e. the leak of volume increases as the square root of time for the static filtration through a filter paper and through the sandstone core. Dual mode filtration diminishes the rate of fluid loss. The model provides also a relation between pressure drop and filtrate rate, which can be used to estimate the permeability of filter cake in the experiment. The leak-off behavior with additive observed in the experiment is well explained by the microstructure of rapid built-up filter cake which is mainly responsible for the control of fluid loss. The role of different components of OBM, e.g. solid particles, emulsion droplets and additives is discussed in the light of our observations.
Chaloupka, Vladimir (Total EP Indonesie) | Descapria, Rio (Total EP Indonesia) | Mahardhini, Antus (Total EP Indonesie) | Coulon, David (Total Austral) | Tran, Quang-buu (Halliburton) | Haekal, Muhammad (Halliburton Indonesia Ltd) | Santoso, Doffie (Halliburton Indonesia) | Amar, Amar (Halliburton Indonesia) | Nusyirwan, Ahmad (Halliburton Indonesia)
Tunu and Tambora gas fields are located in the Mahakam river delta in the province of East Kalimantan, Indonesia. The fields consist of wet gas bearing sand bodies over a height of 13000 ft. Most of the wells are multizone gas producers completed with cemented tubing without primary sand control, and are produced with a bottom-up perforation strategy. The main objective is gas production from the deeper Main Zone layers. The shallower reservoirs prone to sand production were not targeted until recent years. With progressing depletion of deep reservoirs in the Main Zone and bottom up perforation strategy the operator started perforating upper zones. This resulted in an increasing number of interventions or shutting wells in due to sand production.
Due to this fact the operator started considering remedial sand consolidation about 5 years ago. The first successful trials using internally catalysed epoxy resin fluid were prepared in late 2008 and results presented at the 2010 SPE International Symposium and Exhibition on Formation Damage Control (Chaloupka et al. 2010). Initially, these consolidation treatments aimed to find a remedial solution for existing wells choked back or shut in due to sand production. These successful trials, however, quickly turned the project into using consolidation essentially as a primary sand control method.
First treatments targeted weakly consolidated sands in both Tunu and Tambora fields (5,000 to 8,000 ftTVD) using high temperature internally catalysed epoxy consolidation fluid. The treatments showed encouraging results and confirmed this as a viable option for sand control.
In 2010 with growing confidence in the method the operator considered performing sand consolidation in very shallow fully unconsolidated Tunu Shallow zones (2,300 to 5,000 ftTVD) as an alternative to standard single trip multi-zone gravel packs which are conventionally pumped in Tunu Shallow. Five treatments have been performed using a low temperature version of the consolidation fluid with encouraging results. The preliminary performance envelope validated from the treatment is 3 MMscfd of gas per meter perforated or a drawdown of 300 psi.
The paper aims to describe the experience from the initial trials to field application including placement and fluid QAQC procedures as well as treatment results. The failures and difficulties that have been encountered are looked at in more details.
Tambora/Tunu Main Zone
Tunu giant gas field is the major gas supplier of East Kalimantan (Figure 1). Production started in 1990 with hundreds of wells drilled to date. The field is 45 miles long and 9 miles wide. Tunu Main Zone reservoirs are essentially series of stacked fluvio-deltaic sand bodies deposited as channel fill or mouth bars mostly lying between 7,000 and 17,000 ftTVD (Figure 2). A typical channel reservoir consists of medium to fine sandstone, sub rounded, well sorted, well consolidated, with good visual porosity, and occasional coal debris. In the upper section of the Tunu Main Zone porosity averages around 15 % with a maximum of 27 %, with an average permeability around 100 mD and a maximum of 1 D. Mouth bars typically consist of very fine to fine sandstone, sub rounded, well sorted, and well consolidated, with fair visual porosity. Towards the East they become silty with poor porosity. The average porosity in the upper section of the Tunu Main Zone is 13 % with a maximum of 18 %. The average permeability is 10 mD with a maximum of 200 mD.
Frac-packing has gradually become the standard completion technique for sand control in cased holes. As offshore development moves into more challenging deepwater environments, frac-packing technology continues to evolve and therefore brings new issues with the need for a better understanding to resolve them. One of the challenges is solids removal during the reverse out process in high-angle extended-reach large-diameter cased-hole wells.
In high-angle extended reach deepwater drilling, relatively large diameter connections are utilized to handle the tension load and torque. This geometrical environment, when using Bingham plastic or Power-law fluids and sufficient pump rate allows the flow to carry the solids and avoids formation of debris dunes in the areas adjacent to the tool joints. However, during the reverse circulation process, flow phenomena, such as fingering and dilution of the excess slurry with even small volumes of Newtonian brines coupled with low pump rates can create significant difficulties in the removal of solids from the inside of the workstring.
This problem manifests itself when some of sands from these dunes in the workstring are left in the wellbore after the frac-packing process is completed. During tripping of the pipe to extract the service tool, the solids in the workstring fall out of the tube as it goes from high angle sections to vertical. These solids remain in the wellbore and when the dune is of sufficient size or if pushed downhole, during the installation of the production tubulars, this debris can cause issues such as problems with the seal units testing, tagging sufficient debris to not allow seal latch-in, etc. Many times this situation is unavoidable and a special trip should be included to clean the wellbore.
The objective of this work is to study the effectiveness of circulating viscous sweeps to pick up the debris and clean the hole. This can be done by taking multiple aspects into consideration, including the annular and average fluid velocities at different regions of the eccentric annulus, rheological properties of the circulation fluid, density of the fluid and solids, size of the solids, size of the annulus, position of the drillpipe in the annulus or eccentricity, and wellbore angle. The mathematical approach for this research is based on previous works on drilling cuttings removal techniques. A model has then been developed to fit the described completion environment. The model is to estimate fluid velocity in eccentric annulus, based on fundamental concepts of transport phenomena, in combination with particle velocity in order to get an optimum range for the flow rate using the characteristics of Reynolds number and to find a balance between laminar and turbulent flow regimes to pick up the dunes. An experimental apparatus was also designed to simulate the solids removal process after the frac packing completion. Cuttings, suspended in different type of fluids, were circulated in an inclined annulus. The experimental data showed the mobility of solids all around the eccentric annulus and were used to fine-tune the mathematical model.
Utilizing the model and applying the fluid and solids characteristics for a particular completion, one can adjust and control the circulating pump rate in an optimal range. The model allows for the use of best and worst-case scenarios, to eliminate the dunes and also to save time by cleaning the wellbore with appropriate viscous sweeps during the completion and avoiding debris causing completion problems.